Vortex Combustor for Low NOX Emissions when Burning Lean Premixed High Hydrogen Content Fuel

ABSTRACT

A trapped vortex combustor. The trapped vortex combustor is configured for receiving a lean premixed gaseous fuel and oxidant stream, where the fuel includes hydrogen gas. The trapped vortex combustor is configured to receive the lean premixed fuel and oxidant stream at a velocity which significantly exceeds combustion flame speed in a selected lean premixed fuel and oxidant mixture. The combustor is configured to operate at relatively high bulk fluid velocities while maintaining stable combustion, and low NOx emissions. The combustor is useful in gas turbines in a process of burning synfuels, as it offers the opportunity to avoid use of diluent gas to reduce combustion temperatures. The combustor also offers the possibility of avoiding the use of selected catalytic reaction units for removal of oxides of nitrogen from combustion gases exiting a gas turbine.

RELATED PATENT APPLICATIONS

This patent application is a divisional of and claims the benefit ofpriority from prior U.S. patent application Ser. No. 11/365,969, filedon Feb. 28, 2006, which application was a continuation-in-part of, andclaimed the benefit of priority from prior U.S. patent application Ser.No. 10/430,849, filed May 5, 2003, which issued on Feb. 28, 2006 as U.S.Pat. No. 7,003,961B2 entitled “TRAPPED VORTEX COMBUSTOR”; thatapplication claimed the benefit of priority from prior U.S. patentapplication Ser. No. 10/200,780, filed on Jul. 23, 2002, which hasmatured into U.S. Pat. No. 6,694,743 B1, issued Feb. 24, 2004 entitled“ROTARY RAMJET ENGINE WITH FLAMEHOLDER EXTENDING TO RUNNING CLEARANCE ATENGINE CASING INTERIOR WALL”; that application claimed the benefit ofpriority from U.S. Provisional Patent Application Ser. No. 60/386,195,having an effective filing date of Jul. 23, 2001, having been convertedon Jul. 17, 2002 from originally filed U.S. Non-Provisional patentapplication Ser. No. 09/912,265 filed on Jul. 23, 2001. The disclosuresof each of the above patents and patent applications, including thespecification, claims, and figures of the drawing, are each incorporatedherein in their entirety by this reference.

STATEMENT OF GOVERNMENT INTEREST

This invention was made with United States Government support underContract No. DE-FC026-00NT40915 awarded by the United States Departmentof Energy. The Government has certain rights in the invention.

TECHNICAL FIELD

This invention relates to burners and combustors, including highefficiency combustors for gas turbine engines, as well as to processapplications for gas turbine engines utilizing such combustors.

BACKGROUND

The development of novel or improved processes for combustion of highhydrogen content fuels has become increasingly important in view of thedevelopment of various integrated power generation and fuel synthesisprocesses, especially where such processes produce fuels withsignificant hydrogen content. Commercially available gas turbines havetypically been developed for the combustion of natural gas, i.e., amethane-rich fuel with high calorific values in the range of from about800 to about 1200 BTU/scf (British Thermal Units per standard cubicfoot, wherein standard conditions are 14.73 pounds per square inchabsolute and 60° F.). While such gas turbines have been adapted to burncertain syngas fuels, and more specifically fuels with low calorificvalue often in the range of from about 100 to about 300 BTU/scf, gasturbine combustor design features have not generally been optimized forhydrogen content or low grade gaseous fuel applications.

Conventional gas turbine engines encounter two basic difficulties whentransitioning from natural gas to syngas. First, for the same fuel heatinput, the mass flow of a syngas fuel is often four to five timesgreater than that for natural gas, due to the lower heating value of thesyngas fuel. Second, although premixed natural gas and air combustionsystems have become common place for controlling NOx emissions, suchsystems have not been successfully implemented for syngas applications,due to the high hydrogen content of the syngas, and the accompanyingpotential for flashback of the flame into the fuel injection system.Consequently, diffusion flame or “non-premixed” combustors which havebeen used in the combustion of syngas have been configured to controlthe NOx emissions by diluting the syngas with nitrogen, steam or carbondioxide. In such designs, the diluent reduces the flame temperature andconsequently reduces the formation of NOx.

In the combustion of natural gas, dry (i.e., no addition of steam orwater) low NOx (DLN, or “Dry Low NOx”) combustors can achieve less than10 ppmvd (10 parts per million by volume, dry, at 15% Oxygen) NOxemissions with a natural gas fuel. Such DLN combustors rely on thepremix principle, which reduces the combustion flame temperature, andconsequently the NOx emissions. DLN combustors are able to achieve muchlower NOx emissions than diluted non-premixed combustors because ofhigher premixing time prior to the combustion zone.

In high hydrogen content fuel, such as is found in some syngas mixtures(up to 60% hydrogen by volume or more), or in pure hydrogen fuelsources, the flame speeds may be up to as much as six times faster thanthe flame speed that is typical in combustion of natural gas.Consequently, such high flame speed mixtures, whether from syngas basedfuels or from other hydrogen source fuels, makes the use of a DLNcombustion system impossible, because in such a system the flame wouldflash back into the premix zone, and destroy the fuel injectionhardware.

On the other hand, the diluted non-premixed combustors have a chemicalkinetic limit when too much diluent is added for reduction of NOxemissions. The increase in diluent causes flame instability in thecombustion zone, and eventually, combustor flame-out. Consequently, inthe best case, a practical NOx reduction limit for prior art syngascombustors is presently between about 10 and about 20 ppmvd NOx.

In summary, there remains an as yet unmet need for a combustor for a gasturbine engine that may be utilized for the combustion of high hydrogencontent fuels. In order to meet such needs and achieve such goals, it isnecessary to address the basic technical challenges by developing newsystem designs. As described herein, advantageous gas turbine systemdesigns may include the use of a lean premix with high hydrogen contentfuels in combination with the use of trapped vortex combustors.

BRIEF DESCRIPTION OF THE DRAWING

The present invention will be described by way of exemplary embodiments,illustrated in the accompanying drawing in which like reference numeralsdenote like elements, and in which:

FIG. 1 provides a plan view of a novel trapped vortex combustor,illustrating the pre-mixing of fuel such as a hydrogen rich fuel andoxidant, as well as the use of laterally extending mixing struts thatenable combustion gases from the trapped vortex to mix with the incomingfuel-air premix.

FIG. 2 provides an elevation view of an embodiment of a novel trappedvortex combustor configuration, taken along section 2-2 of FIG. 1, moreclearly showing a first bluff body and a second or aft bluff body, whichenables the setup of a stable vortex between the first and second bluffbodies for the combustion of a lean premixed fuel and oxidant mixture,as well as the use of laterally extending struts to promote mixing ofthe entering premix with hot gases that are escaping from a stablevortex between the first bluff body and a second bluff body.

FIG. 3 provides a perspective view of an embodiment of a novel trappedvortex combustor, showing a circulating main vortex similar to thatfirst illustrated in FIG. 1, now showing the use of multiple laterallyextending mixing devices, here depicted in the form of partially airfoilshaped outwardly or laterally extending mixing devices extending intothe bulk lean premixed fuel and oxidant flow adjacent the dump plane ofthe combustor.

FIG. 4 provides a process flow diagram for a prior art IntegratedGasification Combined Cycle (“IGCC”) process, showing the use of adiffusion combustor in a gas turbine, and the feed of compressed airfrom both the gas turbine compressor and from the motor drivencompressor to an air separation unit for the production of oxygen andnitrogen, as well as the use of a selective catalytic reduction hot gasemissions cleanup process subsequent to the gas turbine.

FIG. 5 provides a process flow diagram for an Integrated GasificationCombined Cycle (“IGCC”) process similar to that first described in FIG.4 above, but compared to the process shown in FIG. 4, now eliminates theuse of diluent gas feed to the combustor, and the use of SCR emissionscleanup technology, both of which process steps may be eliminated froman IGCC plant via use of the novel trapped vortex combustor describedand taught herein.

FIG. 6 provides a process flow diagram for a novel IntegratedGasification Combined Cycle (“IGCC”) plant, showing the use of a noveltrapped vortex combustor in a gas turbine, and also showing theelimination of use of selective catalytic reduction or similar processafter the combustion of syngas in the gas turbine for NOx reduction, aswell as the elimination of the use of nitrogen diluent to control NOxemissions from the gas turbine engine.

The foregoing figures, being merely exemplary, contain various elementsthat may be present or omitted from actual embodiments which may beimplemented, depending upon the circumstances. An attempt has been madeto draw the figures in a way that illustrates at least those elementsthat are significant for an understanding of the various embodiments andaspects of the invention. However, various other elements of a noveltrapped vortex combustor, and methods for employing the same in thecombustion of high flame speed fuels such as hydrogen rich syngas, maybe utilized in order to provide a versatile gas turbine engine withnovel trapped vortex combustor for combustion of a fuel-air premix whileminimizing emissions of carbon monoxide and oxides of nitrogen.

DETAILED DESCRIPTION

As depicted in FIG. 1, a novel trapped vortex combustor 10 design hasbeen developed for operation in a low NOx, lean premixed mode onhydrogen-rich fuels, yet accommodates the high flame speed that is acharacteristic of such fuels. In some embodiments, such a combustor 10can achieve extremely low NOx emissions without the added capital andoperating expense of post-combustion treatment of the exhaust gas.Further, such a combustor 10 can eliminate the costly requirement forhigh pressure diluent gas (nitrogen, steam or carbon dioxide) for NOxemissions control.

As easily seen in FIG. 1, in the novel trapped vortex combustor 10design disclosed herein, at least one cavity 12 is provided, having aselected size and shape to stabilize the combustion flame for a selectedfuel composition. Flame stabilization is accomplished by locating a forebody, hereinafter identified as first bluff body 14, upstream of asecond, usually smaller bluff body—commonly referred to as an aft body16. Fuel F, such as a hydrogen rich syngas, is provided by fuel outlets18, and the fuel F is mixed with incoming compressed oxidant containingstream A, which oxidant containing stream A may be a compressed airstream containing both oxygen and nitrogen (or in other embodiments,another inert working fluid, such as steam or carbon dioxide). Thein-flow of bulk fluid continues in the direction of fluid flow referencenumeral 20, ultimately providing a lean fuel-air premixed stream 22 forentry to the combustion zone that occurs at or adjacent cavity 12. Fluidflow issuing from around the first bluff body 14 separates, but insteadof developing shear layer instabilities (that in most circumstancesbecomes the prime mechanism for initiating flame blowout), analternating array of vortices 24 and 26 are conveniently trapped orlocked between the first 14 and second 16 bluff bodies.

In some embodiments of the novel trapped vortex combustor 10 designdisclosed herein, the re-circulation of hot products of combustion intothe incoming, lean premixed fuel and oxidant mixture stream 22 may beaccomplished by incorporating various features. In one embodiment, astable recirculation zone may be generated in on or more vortices, suchas vortices 24 and 26, located adjacent to the main fuel-air flow. Whenthe fluid flow in the vortex or cavity 12 region is designed properly,the flow of the swirling combustion gases comprise one or more vorticesthat are stable, at least with respect to the one or more primarytrapped vortices, and vortex shedding is substantially avoided. Each ofthe one or more stable primary vortices are thus used as a source ofheat, or more precisely, a source of hot products of combustion.Further, heat from the vortex or cavity 12 region must be transportedinto the main entering lean premix fuel and oxidant mixture stream, andmixed into the main flow. As shown in FIG. 1, in one embodiment, thismay be done in part by escape of a portion of combustion gases from thevortices 24 and 26 in cavity 12 outward in the direction of the incominglean premixed fuel and oxidant stream flow 22. In one embodiment, suchmixing may be accomplished by using structures to create a flow ofcombustion gases having a substantial transverse component. In this way,structures such as struts 30 create stagnation zones, from which mixingoccurs, such as via wakes 32 or 34, for example, as seen in FIG. 1. Insuch embodiments, the incoming lean premixed fuel and oxidant mixture 22is at least in part, if not primarily, ignited by lateral mixing,instead of solely by a back-mixing process. In some embodiments, atleast one pair of struts 30 may be provided. Similarly, at least one ofthe at least one pair of struts 30 may include a rear planar portion 31,as can be appreciated from FIG. 2. From FIGS. 1 and 2, it can be seenthat in some embodiments, the planar rear portion 31 may be orientedcoplanar with the rear wall 44 of the first bluff body 14. Further oneor more of the struts 30 may include an upstream portion 33 shaped forlow aerodynamic drag.

In any event, by providing suitable geometric features such as struts30, there is provided in the trapped vortex combustor 10 at least somelateral or transverse flow of hot gases, to provide lateral mixing toignite the incoming fuel-air mixture. By using such structures as struts30 in a mixing technique, the novel trapped vortex combustor 10 designdisclosed herein is believed less sensitive to flame instabilities andother process upsets. This is particularly important when operating nearthe lean flame extinction limit, where small perturbations in the fluidflow can lead to flame extinction.

Thus, in the novel trapped vortex combustor design disclosed herein, thevery stable yet highly energetic primary/core flame zone is veryresistant to external flow field perturbations, and therefore yieldsextended lean and rich blowout limits relative to a dump combustorhaving a simple bluff body component. The unique characteristic of thepresently described novel trapped vortex combustor technology provides afluid dynamic mechanism that can overcome the high flame speed of ahydrogen-rich gas, and thus has the capability to allow combustors tooperate with a hydrogen rich gaseous feed stream with a lean fuel-airpremix composition.

In one embodiment, the novel trapped vortex combustor designconfiguration described herein also has a large flame holding surfacearea, and hence can facilitate the use of a compact primary/core flamezone, which is essential to promoting high combustion efficiency andreduced CO emissions.

As noted in FIGS. 2 and 3, in one embodiment, the trapped vortexcombustor 10 includes a base 40. The first bluff body 14 extends outwardfrom the base 40 for a height or distance of Y₁, and the second bluffbody 16 extends outward from the base for a height or distance of Y₂. Inone embodiment, Y₁ is equal to Y₂, and the combustor 10 also includes aceiling 42, so that during operation, a stabilized vortex of mixing andburning gas 12 is trapped between the rear wall 44 of the first bluffbody 16 and the front wall 46 of the second bluff body 16, and betweenbase 40 and ceiling 42.

In one embodiment, as noted in FIG. 3, between the rear wall 44 of thefirst bluff body 14 and the front wall 46 of the second bluff body 16,at least a portion of the gas from each stabilized vortex 24 and 26 ofmixing and burning gas moves in the bulk fluid flow direction, i.e., thesame direction as the premixed fuel and oxidant mixture stream flow 22shown in FIG. 1. Also, in one embodiment, as noted in FIG. 3, betweenthe rear wall 44 of the first bluff body 14 and the front wall 46 of thesecond bluff body 16, at least a portion of each stabilized vortex ofmixing and burning gas 24 and 26 moves in a direction opposite the bulkfluid flow direction, i.e., opposite the direction as the premixed fueland oxidant mixture inflow 22 shown in FIG. 1.

As better seen in FIGS. 1 and 2, in one embodiment, the novel trappedvortex combustor 10 further comprises one or more outwardly extendingstructures such as struts 30. In some embodiments, struts 30 may includea planar rear portion 31. In some embodiments, the rear planar portion31 may be substantially co-planar with the rear wall 44 of the firstbluff body 14. As seen in FIG. 3, in some embodiments, one or morestruts 30 may be provided. In some embodiments, multiple struts 30 maybe provided in a configuration where they extend outwardly from adjacentthe rear wall 44 of the first bluff body 14. In some embodiments, thestruts 30 may extend transversely with respect to longitudinal axis 50,or may include at least some transverse component, so that circulationof a portion of escaping heat and burning gases flow adjacent struts 30and are thus mixed with an incoming lean premixed fuel and oxidantmixture.

As generally shown in FIGS. 1 through 3, and specifically referenced inFIG. 3, a novel trapped vortex combustor 10 can be provided wherein thecombustor 10 has a central longitudinal axis 50 see FIG. 1) defining anaxial direction. For reference, a combustor may include, extending alongthe longitudinal axis 50, a distance outward toward the ceiling 42 alongan outward direction 52, or alternately in an inward, base direction 54both oriented orthogonal to the axial direction. Also for reference, atrapped vortex combustor 10 may include, space extending in a transversedirection 56 or 58, oriented laterally to the axial direction 50. Apressurizable plenum 60 is provided having a base 40, an outer wall orceiling 42, and in some embodiments, combustor first and secondsidewalls 64 and 66, respectively.

In some embodiments, the first bluff body 14 includes a nose 70 andopposing first 74 and second 76 bluff body sidewalls, as well as rear 44noted above. The second bluff body 16 is located downstream from thefirst bluff body 16. The second bluff body has an upstream side having afront wall 46, a downstream side having a back wall 78, and first 80 andsecond 82 opposing sidewalls.

As seen in FIGS. 1 and 2, a mixing zone 84 is provided downstream of thegaseous fuel inlets 18. The mixing zone 84 is upstream of the rear wall44 of the first bluff body 14. The mixing zone 84 has a length LM_(Z)along the axial direction 50 sufficient to allow mixing of fuel andoxidant, and particularly gaseous fuel and gaseous oxidant, to form alean premixed fuel and oxidant stream 22 having an excess of oxidant.The pressurizable plenum 60, first bluff body 14, and second bluff body16 are size and shaped to receive the lean premixed fuel and oxidantmixture stream 22 at a velocity greater than the combustion flame speedin the lean premixed fuel and oxidant mixture 22 composition. Once thecavity 12 is reached, flow wise, a primary combustion zone of lengthLP_(Z) is provided, wherein one or more stabilized vortices 26 and 26are provided to enhance combustion of the entering fuel. After the aftbluff body 16, combustion burnout zone of length LB_(Z) is provided, ofsufficient length so that final hot combustion exhaust gases, describedbelow, meet the desired composition, especially with respect tominimizing the presence of carbon monoxide.

As seen in FIGS. 1 and 3, in some embodiments, the second bluff body 16is further configured to provide one or more vortex stabilization jets90. Each of the one or more vortex stabilization jets 90 provides anupstream jet of gas in a direction tending to stabilize vortex 22 andvortex 24 in the cavity 12 between the first bluff body 14 and thesecond bluff body 16. In one embodiment, the second bluff body 16 iscoupled to a source of fuel, and in such a case, at least one of thevortex stabilization jets provides an injection stream containing afuel. In such an embodiment, the second bluff body 16 may be coupled toa source of syngas, and in such a case, the fuel comprises a syngas. Inyet other embodiments, the second bluff body 16 is coupled to a sourceof oxidant, and in such cases, one or more of the at least one vortexstabilization jets 90 has an injection jet stream containing an oxidant.In yet another embodiment, the vortex stabilization jets may include afirst jet 90 containing a fuel, and a second jet 92 containing anoxidant. In a yet further embodiment, the vortex stabilization jets maybe used in a process where the second bluff body 16 is coupled to asource of lean premixed fuel and oxidant, and wherein a streamcomprising lean premixed fuel and oxidant is injected through at leastone of the one or more vortex stabilization jets 90.

In any event, the novel trapped vortex combustor 10 includes first 14and second 16 bluff bodies that are spaced apart in a manner that whenthe trapped vortex combustor 10 is in operation, the heat and combustionproducts produced during combustion of the lean premix are continuouslyrecirculated in a recirculation zone in the cavity 12 between the first14 and second 16 bluff bodies, and wherein heat and combustion productsexit longitudinally (reference direction 50) and laterally (which mayinclude transversely such as in reference directions 56 and 58) from thecavity 12 and are employed to continuously ignite a lean premixed fueland oxidant mixture entering the tapped vortex combustor 10. In someembodiments, the lean premixed fuel an oxidant mixture enters adjacentcavity 12, from flow along side of walls 74 and 76 of first bluff body14.

High hydrogen content fuels present a particular problem in that theflame speed during the combustion of a premixed stream of pure hydrogengas and air is approximately six times (6×) that of the flame speed of apremixed stream of natural gas and air. Thus, in order to preventflashback of a flame upstream from a combustor when burning premixedfuels containing hydrogen, the thru-flow velocity needs to be greater,and in some embodiments (depending upon the hydrogen content in the fuelmixture) significantly greater than the flame speed. Such problems arecompounded in lean pre-mix combustor designs since flashback of theflame into the fuel injector may cause severe damage to the hardware,and has the clear potential, for example, to lead to gas turbinefailure. As a result of such factors, in so far as we are aware,presently there are no lean pre-mix gas turbines in operation inindustry on high hydrogen content fuels.

In our method of construction and operation of a suitable novel trappedvortex combustor 10, the bulk fluid velocity 20 entering the combustionzone adjacent trapped vortex 12 exceeds the flame speed of combustionoccurring in the lean premix composition. In some embodiments, the bulkfluid velocity entering the novel trapped vortex combustor 10 exceedsthe flame speed of combustion occurring in the lean premix by a factorof from about 3 to about 6 or thereabouts. Depending upon the actualgaseous composition, fuels containing significant amounts of hydrogenwill have turbulent flame speeds from about thirty five (35) meters persecond to about fifty (50) meters per second. Thus, in order to achievedesirable safety margins necessary when operating on hydrogen richgaseous fuel, the bulk velocity 20 of lean premix may be provided atabout one hundred five (105) meters per second, and up to as much asabout one hundred fifty (150) meters per second, or more. Such bulkpre-mixed fuel velocities allow protection against flash back even whenoperating on high hydrogen content fuels, and thus are a significantimprovement when applied as combustors in gas turbines.

In short, the novel trapped vortex combustor 10 described and claimedherein can provide a significant benefit in gas turbine designs for highhydrogen content fuels. Such fuels may be found in the syngas from coalgasification technology applications, such as Integrated GasificationClean Coal (“IGCC”) plants, or in Combined Cycle Gasification Technology(“CCGT”) plants. Also, in some embodiments, the novel trapped vortexcombustor 10 described and claimed herein may provide a significantbenefit in the design and operation of equipment for the combustion ofhydrogen rich streams in other systems.

As shown in FIG. 4, in a prior art clean coal process plant 118,oxygen-blown coal gasifiers 120 are utilized to generate a synthesis gas122 that is rich in hydrogen and in carbon monoxide. Such synthesis gas122 is typically cleaned in a gas cleanup unit 124, and the cleansynthesis gas 126 is used as a fuel in a gas turbine 128. The synthesisgas 126 is typically burned in a diffusion combustor 130. The productionof raw synthesis gas 122 thus requires an oxygen source, which istypically provided by way of a cryogenic air separation unit (“ASU”)131. Alternately, the oxygen source may be a high temperature iontransport membrane (not shown). As is illustrated in FIG. 4, in typicalprior art process design, a portion 132 of the air 134 for the ASU 131is provided by the compressor 133 of the gas turbine 128, and a portion136 of the air 134 for the ASU 131 is provided by a separate motor 140driven feed air compressor 142. The respective contribution of the gasturbine compressor 133 and the supplemental feed air compressor 142 iscommonly referred to as the “degree of integration”. The “degree ofintegration” varies with the specific plant designs, but the norm isapproximately fifty percent (50%) integration, where half of the ASU 131feed air 134 comes from the gas turbine compressor 133, and half of theASU 131 feed air 134 comes from separate motor 140 drive (typicallyelectric drive) feed air compressor(s) 142.

The heating value of typical cleaned synthesis gas (“syngas”) 126 froman IGCC plant is normally below 250 BTU/scf, (British Thermal Units perstandard cubic foot) which is approximately one-fourth (¼) of theheating value of a typical natural gas supply. Stated another way, four(4) times the gaseous volume of clean syngas 126 fuel is required to befed to a gas turbine 128 in order to generate the same power output thatwould be generated if the gas turbine 128 were, instead, fueledutilizing a typical natural gas supply.

Unfortunately, conventional swirl-stabilized lean pre-mix combustordesigns cannot be used with a hydrogen-rich syngas 126 fuel because ofconcerns over the possibility of flame flashback in a hydrogen richfuel, and over the possibility of auto-ignition in a high pressurepre-mix fuel/oxidant stream. Gas turbine manufacturers offer variousconventional, non-pre-mix diffusion combustor 130 designs that havemarginal emissions signatures. In such conventional prior art diffusioncombustor 130 designs, nitrogen 144 is added as a diluent, in order toreach a desired NOx emissions level, such as a 25 ppm NOx emissionlevel. In other, non-IGCC gas turbine applications, various otherdiluent gases such as CO₂ (carbon dioxide) and H₂O (steam) can also usedfor NOx control, but with the same adverse, efficiency decreasingresults. Note that in the typical IGCC plant 118 as conceptuallydepicted in FIG. 4, although nitrogen 144 diluent comes from the ASU 131as a by-product of the air separation process, there may need to be, atextra capital cost and at extra operating expense, an additional diluentgas compressor (not shown).

For further treatment of the products of combustion to reduce oxides ofnitrogen, a selective catalytic reduction (“SCR”) system 150 may be usedto reach a 3 ppm NOx emission value requirement, as is often establishedby regulation of applicable governmental authorities. In certain SCRsystems 150, optimum reaction temperature for the SCR process may beprovided by linking the SCR system 150 with the heat recovery steamgenerator (“HRSG”) 152. The HRSG 152 may be utilized for recovery ofheat and generation of steam 154 for use in a steam turbine 156 forshaft power, such as via shaft 156 _(S) to an electric generator 157(similar to configuration illustrated in FIG. 6) or for process use (notshown). In any event, condensed steam is collected at a condenser 158and returned as condensate to the HRSG 152. Also, electrical power isgenerated via shaft 128 _(S) power from gas turbine 128 that is used toturn generator 159. Where utilized, the above mentioned electricalgenerator 157 is driven by steam turbine 156.

In such prior art IGCC plants 118, the total combined gaseous productsof combustion flow stream 160, from the added syngas fuel flow volume(up to four times or more by volume, compared to natural gas), and fromthe added nitrogen 144 diluent flow volume, creates a mass flow mismatch(and thus load mismatch) between the compressor section 133 and theturbine section 162 of a gas turbine 128 designed for use on a typicalnatural gas fuel. A higher mass flow rate through the turbine section162 may increase the pressure at the compressor section 133 outlet toomuch, so that the compressor approaches, or if left unaddressed wouldencroach, a compressor surge region, where such total mass flow would nolonger be sustainable. In various plant designs, such a mismatch is“managed” by adjusting the degree of integration, which usually meansremoval of at least a portion of the compressed air mass flow 132 to theASU 131 from the gas turbine compressor 133. Alternately, a gas turbinemanufacturer could add a compressor stage to allow higher overallpressure ratio in the compression cycle. Further, the high mass flow ofsyngas as compared to natural gas might approach the mechanical limitsof a gas turbine rotor to handle turbine power output. Thus, while closecoupling of the ASU 131 and the gas turbine 128 in an IGCC plant wouldseem to be synergistic, in prior art plant designs, there remain variousworkaround issues in plant design with respect to efficient combustionof syngas 126, such designs are subject to various capital costpenalties and/or system efficiency losses, whether from costs of the SCRsystem for NOx cleanup, or for load matching with respect to compressedair requirements, or from nitrogen 144 dilution practice.

By comparison of FIGS. 4 and 5, it is particularly pointed out that theuse of a novel trapped combustor 10 as described and claimed herein toproduce a hot combustion exhaust gas stream 164 would allow theprovision of an IGCC plant that eliminates the practice of use ofnitrogen 144 dilution in burners, and that eliminates the use of an SCRsystem, whether in a high temperature embodiment for direct receipt ofcombustion gases from gas turbine 162′ (not illustrated), or the use ofan SCR system 150 (as shown in a low temperature embodiment inconjunction with the HRSG 152 as noted in FIG. 4).

As can be appreciated from FIG. 5, uncoupling of the gas turbine 128′compressor 133′ with requirement for supply of the ASU 131 also offersthe potential for savings in some fuel synthesis plants, by freeing upthe compressor 133′ so that the parasitic air compression load isreduced. Many of the gas turbine compressors currently available operatemost efficiently at a pressure ratio of about twenty (20), which meansthat when compressing atmospheric air, there is about a three hundred(300) psia (pounds per square inch absolute) discharge pressure.However, since most ASU units 131 presently operate in the one hundredfifty pounds per square inch gauge (150 psig) range, excess compressionwork may sometimes take place in preparation of compressed air feed 134for the ASU 131. However, if in the plant 170 design shown in FIG. 5,valve 172 is closed and all of the feed air 134 to the ASU 131 isprovided using a 4-stage intercooled motor 140′ driven compressor 142′operating at 282.2 psia discharge pressure, the total air compressioncosts would be less than the costs associated with the case shown inFIG. 4 where valve 172 is open and 50% of supply for the air separationunit 131 is provided via the gas turbine compressor 133 bleed airsupply. Further, if all of the ASU 131 feed air were provided by a motor140″ driven intercooled multistage compressor 142″ operating only at onehundred sixty four point seven (164.7) psia discharge pressure, thenthere would be a significant energy savings for the supply of compressedair to the ASU. Moreover, the gas turbine compressor 133′ could in sucha case be designed to solely handle the oxidant supply requirements tocombustor 10 (or to handle compression of an oxidant and an inertworking gas such as carbon dioxide or steam where such fluids are usedto increase work output from turbine 162′ of the gas turbine engine128′), without regard to any integration requirements with the ASU airsupply.

In any event, a novel trapped vortex combustor 10 can be adapted for usein, or in combination with, various types of gas turbines for thecombustion of high hydrogen content fuels, especially such fuels fromvarious types of fuel synthesis plants, such as carbonaceous mattergasification plants, including coal or coke gasification plants. In oneembodiment, this may be made possible by decreasing the mass flowthrough the turbine section. Also, in one embodiment, a novel trappedvortex combustor 10 design can improve the overall cycle efficiency of agas turbine, by decreasing the pressure drop through the trapped vortexcombustor 10, as compared with a prior art diffusion combustor 30. And,such a novel trapped vortex combustor 10 design can extend the leanblowout limit while offering greater turndown, (i.e. load followingcapability), with improved combustion and process stability. In summary,a novel trapped vortex combustor 10 design holds tremendous promise forcombustion of hydrogen rich fuels in various gas turbine 128′applications. Such a design offers improved efficiency, lower emissionslevels, greater flame stability, increased durability, added fuelflexibility, and reduced capital costs, compared to prior art designs.

The novel trapped vortex combustor 10 described and claimed herein maybe utilized in a variety of gaseous fuel synthesis plants that makehydrogen rich fuels. One such plant is an integrated gasificationprocess, as conceptually depicted in FIGS. 5 and 6. In such processes,the gasification unit, shown as gasifier 120, produces a raw synthesisgas 122 from a carbonaceous feed 119, such as coke or coal, to produce asynthesis gas comprising CO and H₂, as well as other contaminants thatvary according to the feed stock.

In a gaseous fuel synthesis process, the synthesis gas (“syngas”)provided by the process may have at least fifteen (15) mole percenthydrogen gas. In other embodiments, the syngas provided by the processmay have at least twenty five (25) mole percent hydrogen gas therein.Depending on feed stock, and the process employed, a synthesis gasprovided by the process may have at least thirty (30) mole percenthydrogen gas. In yet other feed stocks or operating conditions, thesynthesis gas may have at least fifty (50) mole percent hydrogen gas. Instill other embodiments, the synthesis gas may have at least sixty five(65) mole percent hydrogen gas. In yet other embodiments, the synthesisgas may have at least seventy five (75) mole percent hydrogen gas, ormore than seventy five (75) mole percent hydrogen. In some gaseous fuelsynthesis plants, the synthesis gas may be provided at about one hundred(100) mole percent hydrogen.

When a carbonaceous feedstock such as a coal or coke feedstock isutilized in a gasification process, a raw synthesis gas may be cleanedat gas cleanup unit 124 to produce a clean synthesis gas 126. A gasturbine 128′ is provided coupled to an electrical generator 159, forgenerating electrical power. The gas turbine engine 128′ includes acompressor section 133′, a turbine 162′, and a novel trapped vortexcombustor 10. The novel trapped vortex combustor 10 is sized and shapedfor receiving a gaseous fuel F including gas resulting from the cleanupof the raw synthesis gas, via a fuel outlet 18 and a compressed oxidantcontaining stream A (see FIG. 1) and for mixing the gaseous fuel F andthe compressed oxidant containing stream A to form a premixed fuel andoxidant stream 22 having a stoichiometric excess of oxidant. Then, thelean premixed fuel and oxidant stream 22 is fed to the novel trappedvortex combustor 10 at a bulk fluid velocity 20 in excess of the speedof a flame front in a premixed fuel and oxidant mixture stream ofpreselected composition.

As shown in FIG. 1, noted above, the novel trapped vortex combustor 10includes a first bluff body 14 and a second bluff body 16. Thecombustion of the synthesis gas occurs at least in part in cavity 12 toproduce a stabilized vortex 24 and 26 of mixed oxidant and burningsynthesis gas between the first bluff body 14 and the second bluff body16.

In some embodiments, the bulk premixed velocity 20 may be in the rangeof from about one hundred five (105) meters per second to about onehundred fifty (150) meters per second. The fuel F in the lean premixedstream 22 is combusted in the novel trapped vortex combustor 10,primarily at main vortex 12, to create a hot combustion exhaust gasstream 164. The turbine 162′ is turned by expansion of the hotcombustion exhaust gas stream 164, to produce shaft power, and the shaft128′_(S) turns the electrical generator 159 to produce electrical power.

Referring now to FIG. 6, when employed in an IGCC plant, an airseparation unit 131 is normally provided to separate air into a nitrogenrich stream and an oxygen rich stream. In such IGCC plant, the oxygenrich stream is provided as a feed stream to the gasification unit 120.In some embodiments, a motor 140 driven air compressor 142 may beprovided to produce compressed air 134 for feed to the air separationplant 131. As noted in FIG. 5, in some embodiments, a compressor 142″having multiple compression stages and an intercooler 176 can beprovided, and in such case, the process can be operated to recover theheat of compression from air compressed in the motor driven aircompression plant 142″. Further, nitrogen can be collected from thenitrogen rich stream exiting the air separation plant 131. In someembodiments, the nitrogen can be stored as compressed gas, or liquefied,and in any event, collected and either used elsewhere on site or sentoff-site for sale.

In summary, whether for application for combustion of syngas from coalgasification, or for combustion of other high hydrogen content fuels, orfor combustion of other gaseous fuels, a novel trapped vortex combustordesign has now been developed, and initial tests have indicated thatsignificant improvements in emissions may be attained in such a design.And, an important objective of the novel trapped vortex combustor designand operating strategy is to control such emissions. In one embodiment,NOx is expected to be controlled to about 15 ppmvd or lower. In anotherembodiment, NOx is expected to be controlled to 9 ppmvd or lower. In yetanother embodiment, NOx is expected to be controlled to 3 ppmvd orlower. These emissions are stated in parts per million by volume, dry,at fifteen percent (15%) oxygen (“ppmvd”).

As generally described herein, the novel trapped vortex combustor 10described herein is easily adaptable to use in a power generationsystem. Where syngas is burned, the fuel composition may vary widely,depending upon the gasification process selected for use, but broadly,gaseous fuels may have a hydrogen to carbon monoxide mole percent ratioof from about 1/2 to about 1/1. More generally, the novel trapped vortexcombustor 10 described herein may be sized and shaped for operation witha gaseous syngas fuel in a wide range of fuel compositions, and invarious embodiments, may be utilized on syngas containing hydrogen, ormore broadly, with fuels containing hydrogen in the range of from aboutfifteen (15) mole percent to about one hundred (100) mole percent.

The novel trapped vortex combustor 10 design described herein is aunique design which allows use of a gaseous fuel lean pre-mix, and iscapable of handling the high velocity through flow necessary withhydrogen-rich fuels. The technology has experimentally proven to be verystable and exhibits both low pressure drop and low acoustic couplingthroughout its operating range. It is believed that these capabilitiescan potentially allow a gas turbine combustor to burn hydrogen-richsyngas type fuels in a lean pre-mix mode without flashback. Further suchan approach will enable the gas turbine combustor to meet the stringentemissions requirements without after-treatment, and without diluent gas.Such a configuration may also allow the retrofit of certain existingnatural gas fired power plants to clean coal gasification operations,allowing for productive use of the assets currently considered“stranded” by the high cost of natural gas.

In the foregoing description, for purposes of explanation, numerousdetails have been set forth in order to provide a thorough understandingof the disclosed exemplary embodiments for a novel trapped vortexcombustor, and power generation systems employing such a trapped vortexcombustor. However, certain of the described details may not be requiredin order to provide useful embodiments, or to practice a selected orother disclosed embodiments. Further, the description includes, fordescriptive purposes, various relative terms such as adjacent,proximity, adjoining, near, on, onto, on top, underneath, underlying,downward, lateral, base, ceiling, and the like. Such usage should not beconstrued as limiting. That is, terms that are relative only to a pointof reference are not meant to be interpreted as absolute limitations,but are instead included in the foregoing description to facilitateunderstanding of the various aspects of the disclosed embodiments of thepresent invention. And, various steps or operations in a methoddescribed herein may have been described as multiple discreteoperations, in turn, in a manner that is most helpful in understandingthe present invention. However, the order of description should not beconstrued as to imply that such operations are necessarily orderdependent. In particular, certain operations may not need to beperformed in the order of presentation. And, in different embodiments ofthe invention, one or more operations may be eliminated while otheroperations may be added. Also, the reader will note that the phrase “inone embodiment” has been used repeatedly. This phrase generally does notrefer to the same embodiment; however, it may. Finally, the terms“comprising”, “having” and “including” should be considered synonymous,unless the context dictates otherwise.

Importantly, the aspects and embodiments described and claimed hereinmay be modified from those shown without materially departing from thenovel teachings and advantages provided by this invention, and may beembodied in other specific forms without departing from the spirit oressential characteristics thereof. Therefore, the embodiments presentedherein are to be considered in all respects as illustrative and notrestrictive or limiting. As such, this disclosure is intended to coverthe structures described herein and not only structural equivalentsthereof, but also equivalent structures. Numerous modifications andvariations are possible in light of the above teachings. Therefore, theprotection afforded to this invention should be limited only by theclaims set forth herein, and the legal equivalents thereof.

1. An integrated power generation and fuel synthesis process,comprising: (a) providing a fuel synthesis unit to process a feedstockto produce a synthesis gas comprising hydrogen; (b) providing a gasturbine engine and an electrical generator, the gas turbine enginecoupled to the electrical generator for generating electrical power, thegas turbine engine comprising (i) a compressor; (ii) a trapped vortexcombustor, said trapped vortex combustor sized and shaped for receiving(A) the synthesis gas and (B) a compressed oxidant stream, for mixingthe synthesis gas and the compressed oxidant to form a lean premixedfuel and oxidant mixture comprising a stoichiometric excess of oxidant,for feeding the lean premixed fuel and oxidant mixture to the trappedvortex combustor at a bulk fluid velocity in excess of the speed of aflame front in said premixed fuel and oxidant mixture, and (iii) aturbine; (c) compressing an oxidant in the compressor to produce acompressed oxidant stream, and supplying the compressed oxidant streamto the trapped vortex combustor; (d) mixing the synthesis gas with thecompressed oxidant stream to form a lean premixed fuel and oxidantmixture; (e) feeding the lean premixed fuel and oxidant mixture to thetrapped vortex combustor in a bulk fluid flow direction at a bulk fluidvelocity in excess of the speed of a flame front in the lean premixedfuel and oxidant mixture; (f) combusting the fuel in the trapped vortexcombustor, to create a hot combustion gas exhaust stream; (g) expandingthe hot combustion gas exhaust stream in the turbine to produce shaftpower, said shaft power turning the electrical generator to produceelectrical power.
 2. The process as set forth in claim 1, wherein saidfuel synthesis unit comprises a gasification unit.
 3. The process as setforth in claim 2, wherein gasification unit produces said synthesis gasfrom a carbonaceous feedstock.
 4. The process as set forth in claim 3,wherein said carbonaceous feedstock comprises coal.
 5. The process asset forth in claim 3, wherein said carbonaceous feedstock comprisescoke.
 6. The process as set forth in claim 1, wherein said trappedvortex combustor has a cavity between a first bluff body and a secondbluff body, and wherein combusting the synthesis gas occurs at least inpart in a stabilized vortex of mixed oxidant and burning synthesis gascontained in the cavity between said first bluff body and said secondbluff body.
 7. The process as set forth in claim 6, wherein said firstbluff body comprises a rear wall, and said second bluff body comprises afront wall, and wherein between said rear wall and said front wall andadjacent at least a portion of the base, at least a portion of thestabilized vortex of mixing and burning gas moves in the bulk fluid flowdirection.
 8. The process as set forth in claim 7, wherein between saidrear wall of said first bluff body and said front wall of said secondbluff body and adjacent at least a portion of the base, at least aportion of the stabilized vortex of mixing and burning gas movesopposite to the bulk fluid flow direction.
 9. The process as set forthin claim 6, wherein said trapped vortex combustor comprises one or morestruts.
 10. The process as set forth in claim 6, wherein said one ormore struts extend outwardly from said first bluff body.
 11. The processas set forth in claim 6, wherein the lean premixed fuel and oxidantmixture flows to said trapped vortex combustor at a velocity of at least105 meters per second.
 12. The process as set forth in claim 6, whereinthe lean premixed fuel and oxidant mixture flows to said trapped vortexcombustor at a velocity in the range of from about 105 meters per secondto about 150 meters per second.
 13. The process as set forth in claim 6,further comprising feeding the lean premixed gaseous fuel to saidtrapped vortex combustor at a velocity of at least a factor of 3 greaterthan the flame speed of turbulent combustion in said lean premixedgaseous fuel.
 14. The process as set forth in claim 6, wherein saidsecond bluff body further comprises one or more vortex stabilizationjets, and wherein said process further comprises injecting a gaseousstream into said cavity through one or more of said one or more vortexstabilization jets in a direction tending to stabilize the vortex in thecavity between the first bluff body and the second bluff body.
 15. Theprocess as set forth in claim 14, wherein said second bluff body iscoupled to a source of fuel, and wherein the process of injection agaseous stream into said cavity comprises injecting a stream comprisinga fuel or an oxidant through one or more of said one or more vortexstabilization jets.
 16. The process as set forth in claim 14, whereinsaid second bluff body is coupled to a source for a lean premixed fueland oxidant mixture, and wherein said process comprises injecting a leanpremixed fuel and oxidant mixture into the cavity between the firstbluff body and the second bluff body through at least one of said one ormore vortex stabilization jets.
 17. The process as set forth in claim 1,wherein said synthesis gas comprises at least 15 mole percent hydrogengas.
 18. The process as set forth in claim 1, wherein said synthesis gascomprises at least 25 mole percent hydrogen gas.
 19. The process as setforth in claim 1, wherein said synthesis gas comprises at least 30 molepercent hydrogen gas.
 20. The process as set forth in claim 1, whereinsaid synthesis gas comprises at least 50 mole percent hydrogen gas. 21.The process as set forth in claim 1, wherein said synthesis gascomprises at least 65 mole percent hydrogen gas.
 22. The process as setforth in claim 1, wherein said synthesis gas comprises 75 mole percentor more hydrogen gas.
 23. The process as set forth in claim 1, whereinsaid synthesis gas comprises about 100 mole percent hydrogen gas. 24.The process as set forth in claim 1, wherein said trapped vortexcombustor is sized and shaped for operation with a syngas fuelcomprising hydrogen in the range of from about 15 mole percent to about100 mole percent.
 25. The process as set forth in claim 1, wherein saidcompressed oxidant stream further comprises an inert working gas, andwherein said inert working gas comprises one or more gases selected fromthe group consisting of nitrogen, steam, and carbon dioxide.
 26. Theprocess as set forth in claim 1, wherein said trapped vortex combustoroperates without diluent gas addition.